The invention relates to geophysical surveying. More particularly the invention relates to geophysical surveying for resistive and/or conductive bodies. Such bodies might, for example, comprise oil, gas, methane hydrates etc. or other hydrocarbon reserves, or subterranean salt bodies.
Seismic reflection survey techniques are well known and provide well established methods for identifying structural features in subterranean rock strata, e.g., distinct layers and potential fluid reservoirs.
Traditional seismic reflection surveys practiced by the oil industry use stacked seismic data. Until the 1980s it was standard oil industry practice to assume that stacked seismic data only contained information about so-called P-waves, which are the compressional or longitudinally oscillating acoustic waves, and did not include information relating to the shear or transversely oscillating waves, which are known as S-waves. It was known that P-waves and S-waves propagate differently in gas, since P-waves are strongly affected by the incompressibility of gas, whereas S-waves are not. Consequently, it was known that the P- and S-wave responses could be compared as a gas indicator. However, most seismic surveys did not collect S-wave data, so it was assumed that conventional stacked seismic data could only be used for determining geological structure. However, in the 1980s (Ostrander 1984), it was realised that stacked seismic data could also be used as a direct hydrocarbon indicator, since, for non-normal incidence of the seismic ray trace with a layer boundary, incident P-waves partially excite S-waves, and the degree to which this occurs is a function of angle of incidence and is also dependent on the respective acoustic impedances (AIs) of the layers either side of the reflection boundary. The AI of the P-wave is the product of its velocity VP and the density of the medium ρ of the relevant layer. Similarly, the S-wave AI is the product of its velocity VS and the density of the medium ρ. Consequently, by measuring the variation of reflection amplitude versus angle (AVA), or more usually the variation of amplitude versus offset (AVO) for a common depth point (CDP), a direct gas or oil indicator is provided. It is noted that “offset” is the standard term used in the art for the distance between the transmitter and the receiver.
FIG. 1A schematically shows a typical AVO survey carried out in a marine environment.
A surface vessel 14 is illustrated undertaking a seismic AVO survey of a subterranean strata configuration. The subterranean strata configuration in this example includes an overburden layer 8, an underburden layer 9 and a hydrocarbon reservoir 12. The overburden layer 8 is bounded above by the seafloor 6 and below by its interface 5 with the hydrocarbon reservoir 12. The surface vessel 14 floats on the surface 2 of a body of water, in this case seawater 4 of depth h meters. An airgun or other acoustic source 10 is attached to the vessel 14 by a cable 15 by which it is towed. A further cable 14 is also attached to the vessel 14 and has attached to it a plurality of hydrophones or other acoustic sensors 181, 182 . . . 18n which are generally evenly spaced along the further cable 14. The distal end of the further cable 14 has a buoy 17 attached to it which can assist location of the end of the string of hydrophones, and also be used to track the precise location of the end of the string during the survey, for example via a global positioning sensor housed on the buoy 17. The acoustic transmitter 10 and receivers 18 are typically positioned at a height relatively close to the surface 2. In the figure, the incident and reflected ray paths from the transmitter 10 to selected ones of the receivers 18 via the overburden/hydrocarbon interface 5 are also illustrated. As can be seen, the angle of reflection from the vertical θ gradually increases with offset. It will be understood that the data collected at different times in a linear tow path are combined so that the reflections from the same point, i.e. the common depth point, are compared.
Unfortunately, while AVO techniques can often reliably indicate the presence (or absence) of gas, oil or other hydrocarbon, and also the concentration of oil, they are not always able to determine the concentration of gas. Reservoirs are typically characterised by their water, gas and oil saturations (Sw, Sg, So). Clearly, to be commercially viable, a reservoir needs a relatively high gas and/or oil saturation, for example >70%. However, it is well known that AVO methods cannot distinguish between a non-commercial, low-saturation gas reservoir and a commercial, high-saturation gas reservoir. On the other hand, determination of oil saturation is generally possible with AVO methods. A recent summary of AVO techniques can be found in Veeken & Rauch-Davies 2006.
It is known that controlled source electromagnetic (CSEM) survey techniques can be used to overcome limitations of seismic methods in general, and AVO methods in particular, preferably by jointly utilizing the CSEM and seismic data. CSEM methods are a type of electromagnetic survey method, and are to be compared with magnetotelluric (MT) survey methods which employ naturally occurring background radiation as the source.
CSEM techniques distinguish reservoir content on the basis of their differing resistivities. Essentially, hydrocarbon (e.g. oil, gas, hydrate) is relatively resistive, whereas seawater is relatively conductive, so the resistivity of a reservoir layer is a direct indicator of its content. A conductive feature, such as a salt body, is similarly identified by its resistivity contrast with surrounding volumes.
FIG. 1B schematically shows a surface vessel 14 undertaking marine controlled source electromagnetic (CSEM) surveying of a subterranean strata configuration according to a standard technique (see Constable & Weiss 2005 and references therein). The subterranean strata configuration is taken the same as for the above AVO seismic example and the same reference numerals are used for the same features. A submersible vehicle 19 carries a high current electrical source to drive a horizontal electric dipole (HED) antenna 22. The submersible vehicle 19 is attached to the surface vessel 14 by an umbilical cable 16. The HED antenna 22 is supplied with a drive current so that it broadcasts an HED electromagnetic (EM) signal into the seawater 4. The HED transmitter is typically positioned a height of around 50 meters or so above the seafloor 6. An array of remote EM receivers 25 are located on the seafloor 6. The receivers are sensitive to EM fields induced in their vicinity by the HED transmitter, and record signals indicative of these fields for later analysis. Each of the EM receivers 25 includes a data-logging unit 26, a pair of orthogonal antennae 24, a floatation device 28 and a releasable ballast weight (not shown).
In CSEM studies of hydrocarbon reservoirs, it is relevant to note that resistivity scales approximately linearly with gas and/or oil saturation Consequently, if the resistivity can be determined sufficiently accurately, the percentage saturation in the reservoir can in principle be determined. This has been understood, since at least 1994, when it was shown that quantitative determination of oil saturation percentages in a reservoir could be directly determined by CSEM to within a few tens of percent, taking account of the sensitivities and noise levels of the CSEM equipment available at that time, and also provided that the CSEM modelling included additional constraints, e.g. from well logs if available or seismic measurements of the same target volume (Hoerdt & Strack 1994).
A general review of CSEM as carried out on land, which generally uses time domain measurements, can be found in Strack 1992. A general review of marine CSEM, which generally uses frequency domain measurements, can be found in Constable & Weiss 2005 and references therein.
The joint processing of CSEM and seismic data, and in particular CSEM and AVO seismic data, is an area of current interest and a number of recent publications have occurred, such as Hoversten et al 2006, Harris & MacGregor 2006. The overall aim of these joint processing studies is to eliminate ambiguities that exist when processing only CSEM data or only AVO seismic data. Further publications on integration of seismic and electromagnetic measurements, including MT methods, can be found in Dell'Aversana 2006, Jegen 2006, De Stefano and Colombo 2006, Zhanxiang 2006 and Moser 2006.
In Harris & MacGregor 2006 it is described how rock physics relationships can be used to relate reservoir properties such as gas saturation and porosity to electrical and acoustic rock properties, such as resistivity and acoustic impedance. Examples of the models used include Archie's law and Waxman-Smits for relating porosity and resistivity, the Faust equation for relating P-wave velocity to resistivity, and in the seismic case the Hertz-Mindlin theory and Gassmann's equations to relate porosity and fluid saturation to P-wave velocity, S-wave velocity and density. Perturbations on reservoir properties are input to the model to see the effect on the elastic/acoustic properties.